Fracture clusters identification

ABSTRACT

Method for identifying one or more fracture clusters in a formation surrounding a reservoir. In one implementation, the method may include generating a P to S image, comparing the P to S image to one or more images from a borehole, and identifying one or more fracture clusters using the P to S image and the borehole images.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent applicationSer. No. 60/868,508, filed Dec. 4, 2006, and is a continuation of U.S.patent application Ser. No. 11/743,986, filed May 3, 2007, both of whichare incorporated herein by reference for all purposes.

BACKGROUND

1. Field of the Invention

Implementations of various techniques described herein generally relateto sub-surface mapping in the oil and gas industry.

2. Description of the Related Art

The following descriptions and examples do not constitute an admissionas prior art by virtue of their inclusion within this section.

Implementations of various techniques described herein are directed toidentifying fractures and/or fracture clusters that exist in theformation surrounding a reservoir. These fractures may exist due to thenature of the formation, such as rocks, limestones and the like.Knowledge of the fractures or fracture clusters surrounding a reservoirmay be important for well planning, production and the like for variousreasons. For example, fractures may be used to assist the flow ofhydrocarbons from the reservoir to which the fractures are connected.Further, knowledge of the fractures location may assist the geosteeringof the pipes leading to the reservoir.

Currently, geologists use borehole images to identify these fractures.Such borehole images may include ultrasonic borehole images (UBI),oil-based mud images (OBMI), formation microscanned images (FMI) and thelike. Unfortunately, the borehole images only provide images of thesurface of the fractures. The depth, length and shape/pattern of thefractures and the distance between the fractures and the reservoir oftenremain unknown to geologists. As a result, geologists often useprobability density functions to extrapolate the depth, length and shapeof the fractures and the distance between the fractures and thereservoir. Therefore, a need exists in the art for an improved method toidentify fractures or fracture clusters surrounding a reservoir.

SUMMARY

Described herein are implementations of various techniques foridentifying one or more fracture clusters in a formation surrounding areservoir. In one implementation, the fracture clusters may beidentified by generating a P to S image, comparing the P to S image toone or more images from a borehole, and identifying the one or morefracture clusters using the P to S image and the borehole images.

In one implementation, the P to S image may be generated by acquiringseismic data from the formation surrounding the reservoir, separatingthe acquired seismic data into TRY, NRY, HMX and HMN components, andisolating the P to S image from the TRY, NRY, HMX and HMN components.

In one implementation, the P to S image may be isolated from the TRY,NRY, HMX and HMN components by building a model of the reservoir,generating simulated seismic data using the model, determining whether avariance between the simulated seismic data and the acquired seismicdata is below a predetermined value, adjusting the model if the varianceis greater than the predetermined value, and applying the model to theTRY, NRY, HMX and HMN components to isolate the P to S image.Alternatively, the P to S image may be isolated from the TRY, NRY, HMXand HMN components by applying at least one of an FK filter, a medianfilter and a tau p filter to the TRY, NRY, HMX and HMN components.

In one implementation, the P to S image may be compared to one or moreborehole images by generating a fracture density histogram from aborehole image log, identifying areas of non-coherent signal in the P toS image along the borehole, and correlating areas with high levels offracture density in the fracture density histogram with the areas ofnon-coherent signal in the P to S image.

In another implementation, the fracture clusters may be identified bydetermining the areas of non-coherent signal in the P to S image alongthe borehole that correlate with the areas with high levels of fracturedensity as fracture clusters, and determining the areas of non-coherentsignal in the P to S image away from the borehole as fracture clusters.

The fracture clusters may be used in various applications such as tocalculate a well drainage index by defining a fracture zone index basedon the identified fracture clusters and calculating a weighing function,to provide visual insight to at least one of fracture modeling,fractured rock volume and rock properties, to make lithologicalprediction near a borehole, and to make production plans for thereservoir.

Described herein are also implementations of various technologies for acomputer-readable medium having stored thereon computer-executableinstructions which, when executed by a computer, cause the computer to:separate acquired seismic data into TRY, NRY, HMX and HMN components,isolate P, S, P to S and S to P images from the TRY, NRY, HMX and HMNcomponents, select the P to S image, deconvolve the P to S image, stackthe deconvolved P to S image, compare the P to S image to one or moreimages from a borehole, and identify one or more fractures in aformation surrounding a reservoir using the P to S image and theborehole images.

Described herein are also implementations of various technologies for acomputer system, which may include a processor and a memory comprisingprogram instructions executable by the processor to: isolate a P to Simage from seismic data, deconvolve the P to S image, stack the P to Simage, compare the P to S image to one or more borehole images, identifyone or more fractures surrounding a reservoir using the P to S image andthe borehole images and calculate a well drainage index using theidentified fracture clusters.

The above referenced summary section is provided to introduce aselection of concepts in a simplified form that are further describedbelow in the detailed description section. The summary is not intendedto identify key features or essential features of the claimed subjectmatter, nor is it intended to be used to limit the scope of the claimedsubject matter. Furthermore, the claimed subject matter is not limitedto implementations that solve any or all disadvantages noted in any partof this disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of various techniques will hereafter be described withreference to the accompanying drawings. It should be understood,however, that the accompanying drawings illustrate only the variousimplementations described herein and are not meant to limit the scope ofvarious techniques described herein.

FIG. 1 illustrates a method for identifying fracture clusters in aformation surrounding a reservoir in accordance with one or moreimplementations of various techniques described herein.

FIG. 2 illustrates a VSP acquisition system that may be used to acquirethe seismic data in connection with one or more implementations ofvarious techniques described herein.

FIG. 3 illustrates a hodogram analysis that may be used to compute thepolarization dip angle and the azimuth angle at each sensor inaccordance with one or more implementations of various techniquesdescribed herein.

FIG. 4 illustrates angle conversions that may be used to rotate of theX, Y and Z components of the recorded data into the TRY, NRY, HMX andHMN components in accordance with one or more implementations of varioustechniques described herein.

FIG. 5 illustrates the rotated seismic data after rotation into the TRY,NRY, HMX and HMN components in accordance with one or moreimplementations of various techniques described herein.

FIG. 6 illustrates a correlation between a P image and a P to S image inaccordance with one or more implementations of various techniquesdescribed herein.

FIG. 7 illustrates the correlation of a P to S image with boreholeimages in accordance with one or more implementations of varioustechniques described herein.

FIG. 8 illustrates an example of the fracture cluster characterizationschema in accordance with one or more implementations of varioustechniques described herein.

FIG. 9 illustrates a conic shaped VSP area that may be used for weighingfunction calculation in accordance with one or more implementations ofvarious techniques described herein.

FIG. 10 illustrates a computing system, into which implementations ofvarious techniques described herein may be implemented.

DETAILED DESCRIPTION

The discussion below is directed to certain specific implementations. Itis to be understood that the discussion below is only for the purpose ofenabling a person with ordinary skill in the art to make and use anysubject matter defined now or later by the patent “claims” found in anyissued patent herein.

The following paragraphs generally describe one or more implementationsof various techniques directed to identifying and providing a visualimage of fracture clusters in the formation surrounding a borehole toassist in fracture mapping.

In general, P waves, also known as compressional waves, are waves withparticles that oscillate in the direction in which the wave propagates.S waves, also known as shear waves, are waves with particles thatoscillate perpendicular to the direction in which the wave propagates. Pwaves may be generated in at least three ways. That is, P waves may beemitted, produced when other P waves are reflected from surfaces withnormal incidences, and produced when S waves are reflected from surfaceswith non-normal incidences, referred to as converted compressional wavesor S to P waves. Likewise, S waves may be generated in at least threeways. That is, S waves may be emitted, produced when other S waves arereflected from surfaces with normal incidences, and produced when Pwaves are reflected from surfaces with non-normal incidences, referredto as converted shear waves or P to S waves.

During a seismic survey, energy may be emitted by a source, reflected byinterfaces within the earth and recorded by sensors. All of the types ofwaves described above may be present. In general, P waves are typicallyused to produce borehole seismic images. P to S waves are typicallydiscarded as noise. However, interpretation of P to S waves may be usedto determine rock properties, such as fracture density and the like.Because fractures in a formation may affect the rock strength,compressibility and physical behavior of the formation, S waves responddifferently in fractured formations and non-fractured formations and aresensitive to fracture density and signal strength. For example, S wavesmay maintain coherency when reflected off competent rock, but becomenon-coherent when reflected off fractured rock. Coherent waves may be inphase, while non-coherent waves may be out of phase. Accordingly, P to Swaves may be used to identify fracture clusters.

In general, in one or more implementations, borehole seismic data may beseparated into TRY, NRY, HMX and HMN components allowing the P to Swaves in the seismic data to be isolated. The isolated P to S waves maythen be enhanced and correlated with conventional borehole images toprovide an image of fracture clusters surrounding the borehole. Thisprocess may be accomplished for one or more boreholes and a fracturenetwork model may be constructed for an area of interest. One or moretechniques for generating a fracture cluster image in accordance withvarious implementations are described in more detail with reference toFIGS. 1-10 the following paragraphs.

FIG. 1 illustrates a method 100 for identifying fracture clusters in aformation surrounding a reservoir in accordance with one or moreimplementations of various techniques described herein. It should beunderstood that while the operational flow diagram 100 indicates aparticular order of execution of the operations, in otherimplementations, the operations might be executed in a different order.

At step 110, borehole seismic data may be acquired. It should be notedthat the boreholes may be land or marine boreholes. Different types ofborehole seismic surveys may be performed such as a vertical seismicprofile (VSP) and the like. As such, the seismic data may be recorded bymulti-component sensors disposed inside a borehole. FIG. 2 illustrates aVSP acquisition system 200 that may be used to acquire the seismic datain accordance with one or more implementations of various techniquesdescribed herein. The VSP acquisition system 200 may include a source210 configured to discharge waves into the earth 220. The source 210 maybe a vibrator or any other source that may be used to acquire seismicdata. The VSP acquisition system 200 may further include one or moresensors 230 disposed inside a borehole 240. The sensors 230 may beconfigured to record the various waves discharged by the source 210 orthe reflections thereof. The sensors 230 may be geophones, hydrophonesand the like. In one implementation, the sensors 230 may include omnitilt accelerometers with the Z-axis orientated parallel to the boreholeaxis, and the X-axis and Y-axis (i.e., the horizontal components)orientated perpendicular to the borehole axis and mutually orthogonal toeach other.

FIG. 2 further illustrates that P to S waves may be generated from the Pto S conversion at the sea floor 250 as the P waves are reflected offboth competent rock 260 and fractured rock 270. The P to S wavesreflected off the competent rock 260 may maintain coherency, while the Pto S waves reflected off the fractured rock 270 may become non-coherent.

Referring back to FIG. 1, at step 120, once the seismic data have beenrecorded, the data may be separated into TRY (tangent to the incidentray), NRY (normal to the incident ray), HMX (horizontal maximum) and HMN(horizontal minimum) components. To do this, the seismic data recordedon the X, Y and Z axes may first be rotated to find the direction withmaximum energy. This position may be assumed to be the sensor facing thesource position. Once oriented in this position, X, Y and Z planes maybe determined. A polarization analysis, such as a hodogram analysis, maythen be applied to the seismic data such that the P waves and P to Swaves may be maximized on different planes. The azimuth and dip anglesmay then be computed. With the azimuth and dip angle, the TRY, NRY, HMXand HMN coordinates may be computed and the seismic data may bereconstructed along these four axes. This step may be repeated for eachsensor. One example of separating the seismic data into the TRY, NRY,HMX and HMN components in accordance with various implementations isdescribed in more detail with reference to FIGS. 3-5 in the followingparagraphs.

FIG. 3 illustrates a hodogram analysis 300 that may be used to computethe polarization dip angle 310 and the azimuth angle 320 at each sensorin accordance with one or more implementations of various techniquesdescribed herein. The seismic data recorded as an X-axis signal 350,Y-axis signal 360 and Z-axis signal 370 may be oriented. A polarizationanalysis, such as a hodogram analysis, may be applied to the seismicdata to compute the polarization dip angle 310 and azimuth angle 320 ateach sensor. The azimuth angle 320 may be arbitrarily measured relativeto the axis of the X component 330 of the sensor. The dip angle 310 maybe measured relative to the axis of the Z component 350 of the sensor.In addition, the spin direction of particle motion with reference to acoordinate axis, or polarization angle, may be determined.

FIG. 4 illustrates angle conversions that may be used to rotate the X330, Y 340 and Z 350 components of the recorded data into the TRY 410,NRY 420, HMX 430 and HMN 440 components in accordance with one or moreimplementations of various techniques described herein. The original X330, Y 340 and Z 350 components of the recorded data may be rotated intothe TRY 410, NRY 420, HMX 430 and HMN 440 components based on the dipangle 310, azimuth angle 320, and polarization angle 450 calculated inthe polarization analysis.

FIG. 5 illustrates the seismic data after rotation into the TRY 410, NRY420, HMX 430 and HMN 440 components in accordance with one or moreimplementations of various techniques described herein. The seismic datamay be reconstructed into four signals, the TRY signal 450, the NRYsignal 460, the HMX signal 470 and the HMN signal 480. Each of thesesignals may include any combination of P waves, S waves, P to S wavesand S to P waves. In addition, the waves may be a combination ofup-going and down-going waves.

Referring back to FIG. 1, at step 130, the TRY, NRY, HMX and HMNcomponents may be isolated into P waves, S waves, P to S waves and S toP waves. In general, P waves occur more prominently in verticalcomponents of the acquired seismic data, whereas S waves appear moreprominently in the horizontal components of the acquired seismic data.Various techniques may be used to isolate the P waves, S waves, P to Swaves and S to P waves. In one implementation, the oriented wavefieldmade up of the TRY, NRY, HMX and HMN components may be decomposed intoscalar up/down P & S wavefields, referred to as wavefield decomposition.Although the decomposition is described using elastic wavefielddecomposition, it should be understood that in some implementations thedecomposition may be performed using other techniques.

In one implementation, the isolation may be accomplished using amodeling technique. That is, a reservoir model may be built usingvarious reservoir attributes, such as velocity, density, rock layershapes/morphology and the like. Once the model is built, a simulationmay be run using the model to generate simulated seismic data. The modelmay be simulated using a ray tracing operation. The simulated seismicdata may then be compared with the recorded seismic data. If thevariance between the simulated seismic data and the recorded seismicdata is below a pre-determined value, e.g., less than 2%, then the modelmay be applied to the TRY, NRY, HMX and HMN components to isolate the Pwaves, S waves, P to S waves and S to P waves. In anotherimplementation, one or more filters, such as FK filters, median filters,tau p filters and the like, may be used to enhance the isolation of thedata (i.e., the P waves, S waves, P to S waves and S to P waves) afterusing the modeling technique.

In another implementation, in lieu of using the modeling technique, theP waves, S waves, P to S waves and S to P waves may be isolated usingone or more digital filters such as FK filters, median filters, tau pfilters and the like. For example, transforming the seismic data to thefrequency domain, via a Fourier transform, may assist in isolating thevarious wave types because while the waves may overlap in time, thewaves may not overlap in frequency. An FK filter may be applied in thefrequency domain to the TRY, NRY, HMX and HMN components to isolate theP waves, S waves, P to S waves and S to P waves. Once FK filtered, thedata (i.e., the P waves, S waves, P to S waves and S to P waves) maythen be transformed back to the time domain. It should be understoodthat in some implementations the isolation may be performed using stillother techniques such as oblique polarization filtering, parametricdecomposition and the like.

At step 140, the P to S waves of the data may be selected. The P to Swaves may be represented as a P to S image.

At step 150, deconvolution and stacking operations may be applied to theP to S image. Deconvolution may be applied to attenuate the multiples orpseudo reflections from the image. Various deconvolution techniques maybe applied such as semblance deconvolution, prediction deconvolution,waveshaping deconvolution and the like. Stacking may be applied toreduce noise and improve overall data quality. Various stackingtechniques may be applied such as corridor stacking, CDP stacking andthe like.

At step 160, the P to S image may be correlated with the P image fromthe same seismic data to ensure that the P to S waves were adequatelyisolated. It should be noted that in typical seismic data operations,deconvolution and stacking operations may be applied to the P image suchthat the P to S image resulting from step 150 may be correlated with asimilarly processed P image. Correlation of the isolated P to S and Pimages may be used to determine if the P to S waves were adequatelyisolated because of various characteristics of P to S waves such asvelocity. The P to S waves travel with a slower velocity than P waves inthe same Earth medium. Because P to S and P waves have differingvelocities and travel paths, the waves will have differing move-outs ontime-depth axes. In addition, if the P to S waves have been adequatelyisolated, distinct slopes of events for both down and up going P to Swaves will be identifiable and no substantial aliasing of events will bepresent.

FIG. 6 illustrates a correlation between a P image 610 and a P to Simage 620 in accordance with one or more implementations of varioustechniques described herein. A portion of the P image 630 may becorrelated with a portion of the P to S image 640 such that the selectedportions 630 and 640 represent the same area in the formation. Theresolution of the P to S image may be much higher than that of the Pimage due to the fact that the S waves travel perpendicular to themotion of the medium particles.

At step 170, the P to S image may be correlated with borehole images,e.g., OBI, FMI, UBI and the like in order to integrate the data. Forexample, areas along the borehole with high fracture density may becorrelated with areas of non-coherent signal along the borehole in the Pto S image. FIG. 7 illustrates the correlation of a P to S image withborehole images in accordance with one or more implementations ofvarious techniques described herein. A fracture density histogram 710interpreted from a borehole image log may be overlain in time on the Pto S image 720. Areas of non-coherent signal may be identified along atwo way time-depth curve 740 which lies along the borehole interiorsurface. FIG. 7 shows that high levels of fracture density on thefracture density histogram 710 may correlate with areas of non-coherentsignal 730 along the two way time-depth curve 740 on the P to S image720. For example, an area with high levels of fracture density 705 onthe fracture density histogram 710 correlates, shown by the white arrow707, with a specific area of non-coherent signal 730 _(A). Areas ofnon-coherent signal 730 may be interpreted to correspond to fractureclusters. Areas with a high concentration of fracture clusters may bereferred to as fracture zones. As such, it may be inferred from FIG. 7that a number of fracture clusters may be disposed along the borehole,if areas of non-coherent signal 730 are disposed along the two waytime-depth curve 740. It may further be inferred from FIG. 7 thatfracture clusters may be disposed away from the borehole, if areas ofnon-coherent signal 750 are disposed away from the two way time-depthcurve 740. Thus, the P to S image may be used to identify fractureclusters surrounding a borehole.

In FIG. 7, the two borehole UBI images 760 and 770 may be included inthe correlation process to provide additional analysis information, suchas correlation of fracture cluster depth, dip, azimuth attributes andthe like.

At step 180, fracture clusters or fracture zones may be identified inthe area surrounding a borehole using the correlated P to S image andthe borehole images. In this manner, implementations of varioustechniques described herein may allow for more accurate geologicalmodels of fracture networks and provide visual images with reasonableresolution to map fracture clusters affecting the reservoir performance.

In one implementation, the method 100 may be repeated for various areassurrounding a single borehole or multiple boreholes. The resulting datamay be used to construct a fracture network in an area of interest.

In another implementation, prior to the execution of step 120, afracture cluster characterization schema may be developed in thereservoir area of interest. This step may include developing fracturedensity curves interpreted from image logs, fracture strike rosettes,dip rosettes and fracture inclination histograms. FIG. 8 illustrates anexample of the fracture cluster characterization schema in accordancewith one or more implementations of various techniques described herein.The fracture density curve 710 was used to create the composite displayin FIG. 6.

The various techniques described herein may be used in a number ofapplications, such as to provide visual insight to fracture modeling,fractured rock volume and rock properties for geo-mechanics studies; toprovide help in understanding typical lithology behavior around and awayfrom the well bore; to produce reliable results for effective andeconomical decisions on well planning, drilling optimization and welltesting; and the like.

For example, in one application the various techniques may be used in amethod for lithological prediction in the vicinity of the borehole. Inone implementation, well log data may be used to estimate lithology andfacies in the vicinity of the borehole. The non-coherent P to S eventsin the P to S image may then be calibrated with the lithologicalestimate.

As another example, the various techniques may be used in creating aproduction plan for a reservoir. More specifically, the P to S image maybe used to define a 2D or 3D well drainage index. Further, variousimplementations may be used for predicting the productivity of wellsbased on the establishment of a correlation between the well drainageindex, IF_(2D) or IF_(3D), and well productivity data obtained onproducing wells.

Well drainage indices may be calculated by first defining a fracturezone index, F_(2D)(D,r) or F_(3D)(D, r, A), from the fracture clustersor fracture zones identified in step 180 of method 100. The fracturezone index, F_(2D)(D,r) or F_(3D)(D, r, A), is a function of the truevertical depth, D, horizontal distance to the well, r, and azimuth anglewith respect to North, A. It should be noted that if the P to S image isa 2D seismic image, then the fractured zone index may be a 2D indexrepresented as F_(2D)(D,r) which is a function of only the true verticaldepth, D, and horizontal distance to the well, r, and not the azimuthangle with respect to North, A. The fracture zone index of a given pointof coordinates (D, r, A) may have a value of 1, if the point is in afractured zone, or a value of 0, if the point belongs to a non-fracturedzone. The fracture zone index may be based on the manual contouring ofthe relevant fractured zones, as defined by method 100, or it may be theproduct of automatic image processing, i.e., through calculating a localimage coherency index and defining a threshold on this coherency.

The fractured zone index, F_(2D)(D,r) or F_(3D)(D, r, A), may then beused to calculate a well drainage index, IF_(2D) or IF_(3D), which maybe correlated to the surface or volume fraction of the fractured zonesaround the well. The general form of the indices is as follows:

IF _(2D)=∫_(S) F _(2D)(D,r)w _(2D)(D,r)dDdr  (1)

IF _(3D)=∫_(V) F _(3D)(D,r,A)w _(3D)(D,r)dDrdrdA  (2)

The integration may be made over either the 2D cross-sectional area Saround the well containing the seismic data or the 3D volume V aroundthe well containing the seismic data. The weighing function, w_(2D)(D,r)or w_(3D)(D,r), may be introduced to reflect the fact that fracturedzones closer to the well may have a greater importance on the wellproductivity than fractured zones located at a greater distance. Theweighing function may be either a constant or a decreasing function ofthe distance r to the well. The weighing function may also be a functionof the depth D, because the VSP data does not have a uniform extensionaround the well versus depth.

The weighing function for the 2D index (w_(2D)(D,r)) and the weighingfunction for the 3D index (w_(3D)(D,r)) may be different. The weighingfunction may be defined in order to provide a “normalized” indexaccording to the following formulas:

2π∫_(R(D)) w _(3D)(D,r)rdr=1  (3)

∫_(R(D)) w _(2D)(D,r)dr=1  (4)

where R(D) is the range of value for the distance, r, to the well at thedepth D. For a conic shaped VSP area, R(D) is an interval of the form[r_(w), k(D-D₀)] where r_(w), is the wellbore radius and D₀ is the topof the cone. FIG. 9 illustrates a conic shaped VSP area that may be usedfor weighing function calculation in accordance with one or moreimplementations of various techniques described herein.

As an example, the following forms of weighing functions may beselected.

w _(2D)(D,r)=g _(2D)(D)/r  (5)

w _(3D)(D,r)=g _(3D)(D)/r  (6)

Applying the “normalized” index equations (3) and (4) respectively tothe weighing functions (5) and (6) respectively may lead to thefollowing equations.

$\begin{matrix}{{g_{2D}(D)} = {1/{{\ln\left( \frac{k\left( {D - D_{0}} \right.}{r_{w}} \right)}.}}} & (7) \\{{g_{3D}(D)} = {{1/2}{\pi/{\ln\left( \frac{k\left( {D - D_{0}} \right.}{r_{w}} \right)}}}} & (8)\end{matrix}$

In another example, for power laws with exponent n≠1, the followingforms of weighing functions may be selected.

w _(2D)(D,r)=g _(2D)(D)/r ^(n)  (9)

w _(3D)(D,r)=g _(3D)(D)/r ^(n)  (10)

Applying the “normalized” index equations (3) and (4) respectively tothe weighing functions (9) and (10) respectively may lead to thefollowing equations.

$\begin{matrix}{{g_{2D}(D)} = {\left( {n - 1} \right)/\left( {\frac{1}{r_{w}^{n - 1}} - \frac{1}{\left( {k\left( {D - D_{0}} \right)} \right)^{n - 1}}} \right)}} & (11) \\{{g_{3D}(D)} = {{\left( {n - 1} \right)/2}{\pi/\left( {\frac{1}{r_{w}^{n - 1}} - \frac{1}{\left( {k\left( {D - D_{0}} \right)} \right)^{n - 1}}} \right)}}} & (12)\end{matrix}$

Thus, well drainage indices may be calculated. The well drainage indicesmay be correlated to productivity data from producing wells and theresults may be used to form a production plan for the reservoir.

FIG. 10 illustrates a computing system 1000, into which implementationsof various techniques described herein may be implemented. The computingsystem 1000 may include one or more system computers 1030, which may beimplemented as any conventional personal computer or server. However,those skilled in the art will appreciate that implementations of varioustechniques described herein may be practiced in other computer systemconfigurations, including hypertext transfer protocol (HTTP) servers,hand-held devices, multiprocessor systems, microprocessor-based orprogrammable consumer electronics, network PCs, minicomputers, mainframecomputers, and the like.

The system computer 1030 may be in communication with disk storagedevices 1029, 1031, and 1033, which may be external hard disk storagedevices. It is contemplated that disk storage devices 1029, 1031, and1033 are conventional hard disk drives, and as such, will be implementedby way of a local area network or by remote access. Of course, whiledisk storage devices 1029, 1031, and 1033 are illustrated as separatedevices, a single disk storage device may be used to store any and allof the program instructions, measurement data, and results as desired.

In one implementation, seismic data from the receivers may be stored indisk storage device 1031. The system computer 1030 may retrieve theappropriate data from the disk storage device 1031 to process seismicdata according to program instructions that correspond toimplementations of various techniques described herein. The programinstructions may be written in a computer programming language, such asC++, Java and the like. The program instructions may be stored in acomputer-readable medium, such as program disk storage device 1033. Suchcomputer-readable media may include computer storage media andcommunication media. Computer storage media may include volatile andnon-volatile, and removable and non-removable media implemented in anymethod or technology for storage of information, such ascomputer-readable instructions, data structures, program modules orother data. Computer storage media may further include RAM, ROM,erasable programmable read-only memory (EPROM), electrically erasableprogrammable read-only memory (EEPROM), flash memory or other solidstate memory technology, CD-ROM, digital versatile disks (DVD), or otheroptical storage, magnetic cassettes, magnetic tape, magnetic diskstorage or other magnetic storage devices, or any other medium which canbe used to store the desired information and which can be accessed bythe system computer 1030. Communication media may embody computerreadable instructions, data structures, program modules or other data ina modulated data signal, such as a carrier wave or other transportmechanism and may include any information delivery media. The term“modulated data signal” may mean a signal that has one or more of itscharacteristics set or changed in such a manner as to encode informationin the signal. By way of example, and not limitation, communicationmedia may include wired media such as a wired network or direct-wiredconnection, and wireless media such as acoustic, RF, infrared and otherwireless media. Combinations of the any of the above may also beincluded within the scope of computer readable media.

In one implementation, the system computer 1030 may present outputprimarily onto graphics display 1027, or alternatively via printer 1028.The system computer 1030 may store the results of the methods describedabove on disk storage 1029, for later use and further analysis. Thekeyboard 1026 and the pointing device (e.g., a mouse, trackball, or thelike) 1025 may be provided with the system computer 1030 to enableinteractive operation.

The system computer 1030 may be located at a data center remote from thesurvey region. The system computer 1030 may be in communication with thereceivers (either directly or via a recording unit, not shown), toreceive signals indicative of the reflected seismic energy. Thesesignals, after conventional formatting and other initial processing, maybe stored by the system computer 1030 as digital data in the diskstorage 1031 for subsequent retrieval and processing in the mannerdescribed above. While FIG. 10 illustrates the disk storage 1031 asdirectly connected to the system computer 1030, it is also contemplatedthat the disk storage device 1031 may be accessible through a local areanetwork or by remote access. Furthermore, while disk storage devices1029, 1031 are illustrated as separate devices for storing input seismicdata and analysis results, the disk storage devices 1029, 1031 may beimplemented within a single disk drive (either together with orseparately from program disk storage device 1033), or in any otherconventional, manner as will be fully understood by one of skill in theart having reference to this specification.

While the foregoing is directed to implementations of various techniquesdescribed herein, other and further implementations may be devisedwithout departing from the basic scope thereof, which may be determinedby the claims that follow. Although the subject matter has beendescribed in language specific to structural features and/ormethodological acts, it is to be understood that the subject matterdefined in the appended claims is not necessarily limited to thespecific features or acts described above. Rather, the specific featuresand acts described above are disclosed as example forms of implementingthe claims.

1. A method for identifying one or more fracture clusters in a formationsurrounding a reservoir, comprising: generating a seismic signal with aseismic source at a distant location; generating an image from theseismic signal; acquiring seismic data from the formation surroundingthe reservoir; separating the acquired seismic data into TRY, NRY, HMXand HMN components; comparing the image to one or more other images froma borehole; and identifying the one or more fracture clusters using theimage and the other borehole images.